Core sample testing

ABSTRACT

One embodiment of a method of performing a test on a core sample comprises transferring at least a portion of a core sample from a first core containment vessel to a second core containment vessel. The core sample is maintained at a substantially equivalent pressure or placed under a higher pressure during the transfer of the core sample from the first vessel to the second vessel. The method further comprises performing a test on the core sample in a measurement region of the second vessel.

CROSS REFERENCES TO RELATED APPLICATIONS

The present application claims priority under 35 U.S.C. Section 119(e)to U.S. Provisional Patent Application No. 62/881,797, filed Aug. 1,2019, and titled “Core Sample Testing,” U.S. Provisional PatentApplication No. 62/881,787, filed Aug. 1, 2019, and titled “PressurizedReservoir Core Sample Transfer Tool System,” and U.S. Provisional PatentApplication No. 63/050,662, filed Jul. 10, 2020, and titled “PressurizedReservoir Core Sample Transfer Tool System,” the entire contents ofwhich is incorporated herein by reference. The present application isalso related to U.S. patent application Ser. No. 16/944,542, filed Jul.31, 2020, and titled “Pressurized Reservoir Core Sample Transfer ToolSystem,” the entire content of which is incorporated herein byreference.

TECHNICAL FIELD

The present application relates generally to methods of testing coresamples in the hydrocarbon industry.

BACKGROUND

Evaluation of potential oil and gas reservoirs is highly dependent onthe collection and analysis of subsurface core samples removed fromwells. These cores are conventionally extracted in lengths of 30 feet orlonger, each representing a continuous range of drilled depth into theformation. Smaller core plugs are later cut from the core to sample atparticular depths of interest. Sidewall core samples with size on theorder of several inches can also be individually extracted from near thewall of the well. In either case, as the samples are returned from thewell to the surface, they typically experience a change in pressure onthe order of thousands to tens of thousands of pounds per square inch(psi), depending on the total vertical depth traveled. This pressurechange typically affects the phase and composition of the fluidscontained in the rock sample, for example, causing lighter hydrocarbonmolecules to volatilize and leave the sample. It may also result instructural alterations to the rock, such as the formation of fractures,changes in rock fabric, or changes in pore geometry. Laboratory coremeasurements are performed after these composition and structuralchanges have occurred, so the lab data may not necessarily represent thenative state of the samples in their original downhole environment.

Improvements in the testing of core samples is therefore needed.

SUMMARY

In one aspect, a method of performing a test on a core sample retrievedfrom a wellbore of a subterranean reservoir includes transferring atleast a portion of a core sample from a first core containment vessel,or first vessel, to a second core containment vessel, or second vessel.The core sample is maintained at a substantially equivalent pressure orplaced under a higher pressure during the transfer of the core samplefrom the first vessel to the second vessel. The method further includesperforming a test on the core sample in a measurement zone of the secondvessel. In some instances, the first vessel encloses the core sample ina sealed chamber at a pressure above ambient pressure, where thepressure is representative of a pressure from which the core sample wasretrieved. In some instances, the test may be a magnetic resonance test,a computed tomography test, a neutron test, an acoustic test, adielectric test, or any combination thereof.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the exemplary embodiments of thepresent invention and the advantages thereof, reference is now made tothe following description in conjunction with the accompanying drawings,which are briefly described as follows.

FIG. 1 shows a tool system for transferring pressurized reservoir coresamples, according to an exemplary embodiment.

FIG. 2 is a flowchart illustrating a method of performing a test on acore sample, according in an exemplary embodiment.

DETAILED DESCRIPTION

TERMINOLOGY: The following terms will be used throughout thespecification and will have the following meanings unless otherwiseindicated.

Formation: Hydrocarbon exploration processes, hydrocarbon recovery (alsoreferred to as hydrocarbon production) processes, or any combinationthereof may be performed on a formation. The formation refers topractically any volume under a surface. For example, the formation maybe practically any volume under a terrestrial surface (e.g., a landsurface), practically any volume under a seafloor, etc. A water columnmay be above the formation, such as in marine hydrocarbon exploration,in marine hydrocarbon recovery, etc. The formation may be onshore. Theformation may be offshore (e.g., with shallow water or deep water abovethe formation). The formation may include faults, fractures,overburdens, underburdens, salts, salt welds, rocks, sands, sediments,pore space, etc. Indeed, the formation may include practically anygeologic point(s) or volume(s) of interest (such as a survey area) insome embodiments.

The formation may include hydrocarbons, such as liquid hydrocarbons(also known as oil or petroleum), gas hydrocarbons (e.g., natural gas),solid hydrocarbons (e.g., asphaltenes or waxes), a combination ofhydrocarbons (e.g., a combination of liquid hydrocarbons, gashydrocarbons, and solid hydrocarbons), etc. Light crude oil, medium oil,heavy crude oil, and extra heavy oil, as defined by the AmericanPetroleum Institute (API) gravity, are examples of hydrocarbons.Examples of hydrocarbons are many, and hydrocarbons may include oil,natural gas, kerogen, bitumen, clathrates (also referred to ashydrates), etc. The hydrocarbons may be discovered by hydrocarbonexploration processes.

The formation may also include at least one wellbore. For example, atleast one wellbore may be drilled into the formation in order to confirmthe presence of the hydrocarbons. As another example, at least onewellbore may be drilled into the formation in order to recover (alsoreferred to as produce) the hydrocarbons. The hydrocarbons may berecovered from the entire formation or from a portion of the formation.For example, the formation may be divided into one or more hydrocarbonzones, and hydrocarbons may be recovered from each desired hydrocarbonzone. One or more of the hydrocarbon zones may even be shut-in toincrease hydrocarbon recovery from a hydrocarbon zone that is notshut-in.

The formation, the hydrocarbons, or any combination thereof may alsoinclude non-hydrocarbon items. For example, the non-hydrocarbon itemsmay include connate water, brine, tracers, items used in enhanced oilrecovery or other hydrocarbon recovery processes, items from othertreatments (e.g., items used in conformance control), etc.

In short, each formation may have a variety of characteristics, such aspetrophysical rock properties, reservoir fluid properties, reservoirconditions, hydrocarbon properties, or any combination thereof. Forexample, each formation (or even zone or portion of the formation) maybe associated with one or more of: temperature, porosity, salinity,permeability, water composition, mineralogy, hydrocarbon type,hydrocarbon quantity, reservoir location, pressure, etc. Indeed, thoseof ordinary skill in the art will appreciate that the characteristicsare many, including, but not limited to: shale gas, shale oil, tightgas, tight oil, tight carbonate, carbonate, vuggy carbonate,unconventional (e.g., a rock matrix with an average pore size less than1 micrometer), diatomite, geothermal, mineral, metal, a formation havinga permeability in the range of 0.01 microdarcy to 10 millidarcy, aformation having a permeability in the range of 10 millidarcy to 40,000millidarcy, etc.

The terms “formation”, “subsurface formation”, “hydrocarbon-bearingformation”, “reservoir”, “subsurface reservoir”, “subsurface region ofinterest”, “subterranean reservoir”, “subsurface volume of interest”,and the like may be used synonymously. The terms “formation”,“hydrocarbons”, and the like are not limited to any description orconfiguration described herein.

Wellbore: A wellbore refers to a single hole, usually cylindrical, thatis drilled into the formation for hydrocarbon exploration, hydrocarbonrecovery, surveillance, or any combination thereof. The wellbore isusually surrounded by the formation and the wellbore may be configuredto be in fluidic communication with the formation (e.g., viaperforations). The wellbore may also be configured to be in fluidiccommunication with the surface, such as in fluidic communication with asurface facility that may include oil/gas/water separators, gascompressors, storage tanks, pumps, gauges, sensors, meters, pipelines,etc.

The wellbore may be used for injection (sometimes referred to as aninjection wellbore) in some embodiments. The wellbore may be used forproduction (sometimes referred to as a production wellbore) in someembodiments. The wellbore may be used for a single function, such asonly injection, in some embodiments. The wellbore may be used for aplurality of functions, such as production then injection, in someembodiments. The use of the wellbore may also be changed, for example, aparticular wellbore may be turned into an injection wellbore after adifferent previous use as a production wellbore. The wellbore may bedrilled amongst existing wellbores, for example, as an infill wellbore.A wellbore may be utilized for injection and a different wellbore may beused for hydrocarbon production, such as in the scenario thathydrocarbons are swept from at least one injection wellbore towards atleast one production wellbore and up the at least one productionwellbore towards the surface for processing. On the other hand, a singlewellbore may be utilized for injection and hydrocarbon production, suchas a single wellbore used for hydraulic fracturing and hydrocarbonproduction. A plurality of wellbores (e.g., tens to hundreds ofwellbores) are often used in a field to recover hydrocarbons.

The wellbore may have straight, directional, or a combination oftrajectories. For example, the wellbore may be a vertical wellbore, ahorizontal wellbore, a multilateral wellbore, an inclined wellbore, aslanted wellbore, etc. The wellbore may include a change in deviation.As an example, the deviation is changing when the wellbore is curving.In a horizontal wellbore, the deviation is changing at the curvedsection (sometimes referred to as the heel). As used herein, ahorizontal section of a wellbore is drilled in a horizontal direction(or substantially horizontal direction). For example, a horizontalsection of a wellbore is drilled towards the bedding plane direction. Ahorizontal section of a wellbore may be, but is not limited to, ahorizontal section of a horizontal wellbore. On the other hand, avertical wellbore is drilled in a vertical direction (or substantiallyvertical direction). For example, a vertical wellbore is drilledperpendicular (or substantially perpendicular) to the bedding planedirection.

The wellbore may include a plurality of components, such as, but notlimited to, a casing, a liner, a tubing string, a heating element, asensor, a packer, a screen, a gravel pack, artificial lift equipment(e.g., an electric submersible pump (ESP)), etc. The “casing” refers toa steel pipe cemented in place during the wellbore construction processto stabilize the wellbore. The “liner” refers to any string of casing inwhich the top does not extend to the surface but instead is suspendedfrom inside the previous casing. The “tubing string” or simply “tubing”is made up of a plurality of tubulars (e.g., tubing, tubing joints, pupjoints, etc.) connected together. The tubing string is lowered into thecasing or the liner for injecting a fluid into the formation, producinga fluid from the formation, or any combination thereof. The casing maybe cemented in place, with the cement positioned in the annulus betweenthe formation and the outside of the casing. The wellbore may alsoinclude any completion hardware that is not discussed separately. If thewellbore is drilled offshore, the wellbore may include some of theprevious components plus other offshore components, such as a riser.

The wellbore may also include equipment to control fluid flow into thewellbore, control fluid flow out of the wellbore, or any combinationthereof. For example, each wellbore may include a wellhead, a BOP,chokes, valves, or other control devices. These control devices may belocated on the surface, under the surface (e.g., downhole in thewellbore), or any combination thereof. In some embodiments, the samecontrol devices may be used to control fluid flow into and out of thewellbore. In some embodiments, different control devices may be used tocontrol fluid flow into and out of the wellbore. In some embodiments,the rate of flow of fluids through the wellbore may depend on the fluidhandling capacities of the surface facility that is in fluidiccommunication with the wellbore. The control devices may also beutilized to control the pressure profile of the wellbore.

The equipment to be used in controlling fluid flow into and out of thewellbore may be dependent on the wellbore, the formation, the surfacefacility, etc. However, for simplicity, the term “control apparatus” ismeant to represent any wellhead(s), BOP(s), choke(s), valve(s),fluid(s), and other equipment and techniques related to controllingfluid flow into and out of the wellbore.

The wellbore may be drilled into the formation using practically anydrilling technique and equipment known in the art, such as geosteering,directional drilling, etc. Drilling the wellbore may include using atool, such as a drilling tool that includes a drill bit and a drillstring. Drilling fluid, such as drilling mud, may be used while drillingin order to cool the drill tool and remove cuttings. Other tools mayalso be used while drilling or after drilling, such asmeasurement-while-drilling (MWD) tools, seismic-while-drilling (SWD)tools, wireline tools, logging-while-drilling (LWD) tools, or otherdownhole tools. After drilling to a predetermined depth, the drillstring and the drill bit are removed, and then the casing, the tubing,etc. may be installed according to the design of the wellbore.

The equipment to be used in drilling the wellbore may be dependent onthe design of the wellbore, the formation, the hydrocarbons, etc.However, for simplicity, the term “drilling apparatus” is meant torepresent any drill bit(s), drill string(s), drilling fluid(s), andother equipment and techniques related to drilling the wellbore.

The term “wellbore” may be used synonymously with the terms “borehole,”“well,” or “well bore.” The term “wellbore” is not limited to anydescription or configuration described herein.

Hydrocarbon recovery: The hydrocarbons may be recovered (sometimesreferred to as produced) from the formation using primary recovery(e.g., by relying on pressure to recover the hydrocarbons), secondaryrecovery (e.g., by using water injection (also referred to aswaterflooding) or natural gas injection to recover hydrocarbons),enhanced oil recovery (EOR), or any combination thereof. Enhanced oilrecovery or simply EOR refers to techniques for increasing the amount ofhydrocarbons that may be extracted from the formation. Enhanced oilrecovery may also be referred to as tertiary oil recovery. Secondaryrecovery is sometimes just referred to as improved oil recovery orenhanced oil recovery. EOR processes include, but are not limited to,for example: (a) miscible gas injection (which includes, for example,carbon dioxide flooding), (b) chemical injection (sometimes referred toas chemical enhanced oil recovery (CEOR) that includes, for example,polymer flooding, alkaline flooding, surfactant flooding, conformancecontrol, as well as combinations thereof such as alkaline-polymer (AP)flooding, surfactant-polymer (SP) flooding, oralkaline-surfactant-polymer (ASP) flooding), (c) microbial injection,(d) thermal recovery (which includes, for example, cyclic steam andsteam flooding), or any combination thereof. The hydrocarbons may berecovered from the formation using a fracturing process. For example, afracturing process may include fracturing using electrodes, fracturingusing fluid (oftentimes referred to as hydraulic fracturing), etc. Thehydrocarbons may be recovered from the formation using radio frequency(RF) heating. Other hydrocarbon recovery processes may also be utilizedto recover the hydrocarbons. Furthermore, those of ordinary skill in theart will appreciate that one hydrocarbon recovery process may also beused in combination with at least one other recovery process orsubsequent to at least one other recovery process. Moreover, hydrocarbonrecovery processes may also include stimulation or other treatments.

Other definitions: The term “proximate” is defined as “near”. If item Ais proximate to item B, then item A is near item B. For example, in someembodiments, item A may be in contact with item B. For example, in someembodiments, there may be at least one barrier between item A and item Bsuch that item A and item B are near each other, but not in contact witheach other. The barrier may be a fluid barrier, a non-fluid barrier(e.g., a structural barrier), or any combination thereof. Both scenariosare contemplated within the meaning of the term “proximate.”

The terms “comprise” (as well as forms, derivatives, or variationsthereof, such as “comprising” and “comprises”) and “include” (as well asforms, derivatives, or variations thereof, such as “including” and“includes”) are inclusive (i.e., open-ended) and do not excludeadditional elements or steps. For example, the terms “comprises” and/or“comprising,” when used in this specification, specify the presence ofstated features, integers, steps, operations, elements, and/orcomponents, but do not preclude the presence or addition of one or moreother features, integers, steps, operations, elements, components,and/or groups thereof. Accordingly, these terms are intended to not onlycover the recited element(s) or step(s), but may also include otherelements or steps not expressly recited. Furthermore, as used herein,the use of the terms “a” or “an” when used in conjunction with anelement may mean “one,” but it is also consistent with the meaning of“one or more,” “at least one,” and “one or more than one.” Therefore, anelement preceded by “a” or “an” does not, without more constraints,preclude the existence of additional identical elements.

The use of the term “about” applies to all numeric values, whether ornot explicitly indicated. This term generally refers to a range ofnumbers that one of ordinary skill in the art would consider as areasonable amount of deviation to the recited numeric values (i.e.,having the equivalent function or result). For example, this term can beconstrued as including a deviation of ±10 percent of the given numericvalue provided such a deviation does not alter the end function orresult of the value. Therefore, a value of about 1% can be construed tobe a range from 0.9% to 1.1%. Furthermore, a range may be construed toinclude the start and the end of the range. For example, a range of 10%to 20% (i.e., range of 10%-20%) includes 10% and also includes 20%, andincludes percentages in between 10% and 20%, unless explicitly statedotherwise herein. Similarly, a range of between 10% and 20% (i.e., rangebetween 10%-20%) includes 10% and also includes 20%, and includespercentages in between 10% and 20%, unless explicitly stated otherwiseherein.

The term “if” may be construed to mean “when” or “upon” or “in responseto determining” or “in accordance with a determination” or “in responseto detecting,” that a stated condition precedent is true, depending onthe context. Similarly, the phrase “if it is determined [that a statedcondition precedent is true]” or “if [a stated condition precedent istrue]” or “when [a stated condition precedent is true]” may be construedto mean “upon determining” or “in response to determining” or “inaccordance with a determination” or “upon detecting” or “in response todetecting” that the stated condition precedent is true, depending on thecontext.

It is understood that when combinations, subsets, groups, etc. ofelements are disclosed (e.g., combinations of components in acomposition, or combinations of steps in a method), that while specificreference of each of the various individual and collective combinationsand permutations of these elements may not be explicitly disclosed, eachis specifically contemplated and described herein. By way of example, ifan item is described herein as including a component of type A, acomponent of type B, a component of type C, or any combination thereof,it is understood that this phrase describes all of the variousindividual and collective combinations and permutations of thesecomponents. For example, in some embodiments, the item described by thisphrase could include only a component of type A. In some embodiments,the item described by this phrase could include only a component of typeB. In some embodiments, the item described by this phrase could includeonly a component of type C. In some embodiments, the item described bythis phrase could include a component of type A and a component of typeB. In some embodiments, the item described by this phrase could includea component of type A and a component of type C. In some embodiments,the item described by this phrase could include a component of type Band a component of type C. In some embodiments, the item described bythis phrase could include a component of type A, a component of type B,and a component of type C. In some embodiments, the item described bythis phrase could include two or more components of type A (e.g., A1 andA2). In some embodiments, the item described by this phrase couldinclude two or more components of type B (e.g., B1 and B2). In someembodiments, the item described by this phrase could include two or morecomponents of type C (e.g., C1 and C2). In some embodiments, the itemdescribed by this phrase could include two or more of a first component(e.g., two or more components of type A (A1 and A2)), optionally one ormore of a second component (e.g., optionally one or more components oftype B), and optionally one or more of a third component (e.g.,optionally one or more components of type C). In some embodiments, theitem described by this phrase could include two or more of a firstcomponent (e.g., two or more components of type B (B1 and B2)),optionally one or more of a second component (e.g., optionally one ormore components of type A), and optionally one or more of a thirdcomponent (e.g., optionally one or more components of type C). In someembodiments, the item described by this phrase could include two or moreof a first component (e.g., two or more components of type C (C1 andC2)), optionally one or more of a second component (e.g., optionally oneor more components of type A), and optionally one or more of a thirdcomponent (e.g., optionally one or more components of type B).

This written description uses examples to disclose the invention,including the best mode, and also to enable any person skilled in theart to make and use the invention. The patentable scope is defined bythe claims, and may include other examples that occur to those skilledin the art. Such other examples are intended to be within the scope ofthe claims if they have elements that do not differ from the literallanguage of the claims, or if they include equivalent elements withinsubstantial differences from the literal language of the claims.

Unless defined otherwise, all technical and scientific terms used hereinhave the same meanings as commonly understood by one of skill in the artto which the disclosed invention belongs. All citations referred hereinare expressly incorporated by reference.

OVERVIEW: One embodiment of a method of performing a test on a coresample comprises transferring at least a portion of a core sample from afirst core containment vessel, or first vessel, or retrieval vessel, toa second core containment vessel, or second vessel, or testing vessel,and performing a test on the core sample in the second vessel. The coresample is maintained at a substantially equivalent pressure or placedunder a higher pressure during the transfer of the core sample from thefirst vessel to the second vessel. By doing so, the test and the testresults may be more accurate (e.g., more representative of reservoirconditions). For example, embodiments consistent with the presentdisclosure may be utilized for characterizing the core samples and theirfluid contents, both while at the initial received pressure and duringthe depressurization process. Furthermore, embodiments consistent withthe present disclosure may be utilized for characterizing core samplesthat have been recovered and maintained at elevated pressure and/ortemperature. In certain embodiments, the core samples have beenmaintained at the original reservoir pressure and/or temperature, sothat there are minimal or no structural changes to the samples, and/orminimal or no changes to the composition and phase of the fluidscontained in the samples. In certain embodiments, the core samples havebeen maintained at representative conditions. In certain exemplaryembodiments, representative conditions may refer to when the coresamples have been maintained at an elevated pressure and/or temperaturethat is/are representative of the original reservoir pressure and/ortemperature, such that the fluids contained in the samples have notundergone a phase transition (e.g., at a bubble point or dew point) andthe fluid contents of the samples remain representative of reservoirconditions. Additionally, in certain exemplary embodiments,representative conditions may refer to the structure of the sampleshaving changed less than if the pressure and/or temperature had beenallowed to reach ambient conditions. In some embodiments, a non-misciblefluid, such as a fluorocarbon, has been deployed surrounding the samplesin the first vessel to further minimize changes to the composition ofthe fluids contained in the samples due to a pressure decrease from thereservoir to the surface.

The present invention may be better understood by reading the followingdescription of non-limitative embodiments with reference to the attacheddrawings. In the interest of clarity, not all features of an actualimplementation are described in this specification. One of ordinaryskill in the art will appreciate that in the development of any suchactual embodiment, numerous implementation-specific decisions must bemade to achieve the developers' specific goals, such as compliance withsystem-related and business-related constraints, which will vary fromone implementation to another. Moreover, it will be appreciated thatsuch a development effort might be complex and time-consuming, but wouldnevertheless be a routine undertaking for those of ordinary skill in theart having the benefit of this disclosure.

FIG. 1 shows a side perspective view of a tool system 100 fortransferring pressurized reservoir core samples at a point in time inaccordance with certain example embodiments. The system 100 includes afirst vessel 105 and a second vessel 110 that are detachably coupled toa valve assembly 115. The first vessel 105 is designed to collect and/orhouse one or more pressurized subterranean core samples taken from thesidewall of a wellbore. The first vessel 105 is removed from a bottomhole assembly (BHA) or general core retrieval tooling for use in theexample system 100. The first vessel 105 is known in the art. The firstvessel 105 may be constructed of magnetic and/or metallic material. As aresult, it is not possible to test the pressurized subterranean coresamples disposed within the first vessel 105 using technologies such asNMR. Example embodiments of the tool system 100 are designed to transferthe subterranean core samples under the same pressure to a secondvessel, which has a non-metallic and/or non-magnetic measurement region110 a that has a low noise profile when subjected to some of the testingtechnologies (e.g. NMR) used to test subterranean core samples. Incertain exemplary embodiments, the second vessel 110 is constructed bywrapping low/no noise resin and fiber material around a non-metallicand/or non-magnetic tube to provide structural integrity. In certainother exemplary embodiments, the second vessel 110, is constructed usinga low/no noise glass/thermoplastic composite. As used herein, no noisematerials may refer to materials that give no signal in a test performedon the second vessel 110. In certain exemplary embodiments, low noisematerials may refer to materials that give an acceptably small signal ina test performed on the second vessel, that do not interfere with orotherwise obscure the signal given in the test by the core samplescontained in the measurement zone 110 a of the second vessel 110.

FIG. 2 illustrates a method 200 of performing a test on a core sample,according to an exemplary embodiment. At 205, the method 200 includestransferring at least a portion of a core sample from a first corecontainment vessel, or first vessel, to a second core containmentvessel, or second vessel. In certain embodiments, the core sample (orsimply “sample”) comprises rock and fluid retrieved from a wellbore of asubterranean reservoir. For example, in some embodiments, the coresample is retrieved from a wellbore from a subterranean reservoir usinga pressure coring process. In one embodiment, transferring at least aportion of a core sample from a first vessel to a second vessel furthercomprises subsampling the core sample. As an example, a core sample witha length of about 3 meters may be retrieved and stored in the firstvessel. Subsequently, a subsample may be obtained from the core samplethat is 3 meters long, and the subsample may be transferred to thesecond vessel while maintaining pressure and/or temperature. In someembodiments, one or more subsamples may be generated in the firstvessel, in a transfer tool, or any combination thereof.

In some embodiments, the core sample is retrieved from a wellbore from asubterranean reservoir using a rotary sidewall coring process. Moreover,in one embodiment, the core sample comprises a plurality of rock andfluid samples retrieved from various depths in a wellbore of asubterranean reservoir, for example, using a rotary sidewall coringprocess. However, it is possible to retrieve a single core sample withthe rotary sidewall coring process. The core sample may comprise asidewall core sample or practically any other core sample that may beretrieved from the subterranean reservoir.

In some embodiments, a single core sample may be at least 1 inch inlength (e.g., at least 1.25 inches in length, at least 1.5 inches inlength, or at least 1.75 inches in length). In some embodiments, asingle core sample may be 2 inches or less in length (e.g., 1.75 inchesor less in length, 1.5 inches or less in length, or 1.25 inches or lessin length). The length of the single core sample may be in an amountranging from any of the minimum values described above to any of themaximum values described above. For example, in some embodiments, asingle core sample may be between 1 inch and 2 inches (e.g., between1.25 inches and 2 inches or between 1.5 inches and 2 inches). In someembodiments, a single core sample may be any length less than 1 inch,although tests on such samples may yield a larger error than for sampleshaving a length at least 1 inch.

The second vessel may include at least 1 core sample, and a plurality ofcore samples in an amount up to the capacity of the measurement zone orregion of the second vessel. In some embodiments, the second vesselincludes at least 2 core samples. In some embodiments, a plurality ofcore samples may include at least 5 core samples (e.g., at least 6 coresamples, at least 7 core samples, at least 8 core samples, at least 9core samples, at least 10 core samples, at least 11 core samples, atleast 12 core samples, at least 13 core samples, or at least 14 coresamples). In some embodiments, a plurality of core samples may include15 core samples or less (e.g., 14 core samples or less, 13 core samplesor less, 12 core samples or less, 11 core samples or less, 10 coresamples or less, 9 core samples or less, 8 core samples or less, 7 coresamples or less, or 6 core samples or less). The quantity of coresamples in a plurality of core samples may be in an amount ranging fromany of the minimum values described above to any of the maximum valuesdescribed above. For example, in some embodiments, a plurality of coresamples may include between 5 core samples and 15 core samples (e.g.,between 5 core samples and 10 core samples, between 10 core samples and12 core samples, between 10 core samples and 15 core samples, between 11core samples and 15 core samples, or between 12 core samples and 15 coresamples). As an example, the first vessel may contain 10-15 core sampleswith each core sample having a length of between 1 inch and 2 inches,and all of those core samples may be transferred from the first vesselto the second vessel.

Thus, those of ordinary skill in the art will appreciate that the term“core sample” may therefore include practically any core sample that maybe transferred from the first vessel to the second vessel, such as, butnot limited to, transferring a single core sample from the first vesselto the second vessel, transferring a plurality of core samples from thefirst vessel to the second vessel, transferring at least a portion of acore sample from the first vessel to the second vessel (e.g., viasubsampling the core sample and transferring the subsample from thefirst vessel to the second vessel, or by transferring less than all coresamples available in the first vessel to the second vessel such asleaving 9 core samples in the first vessel and only transferring 1 coresample from the first vessel to the second vessel), etc.

Turning to the vessels, in some embodiments, the test on the core sampleis unable to be performed using the first vessel due to interferencebetween the first vessel and equipment used for the test. For example,the first vessel comprises a magnetic material that may interfere withthe test. For example, the first vessel comprises a metallic materialthat may interfere with the test. For example, the first vesselcomprises magnetic and metallic material that may interfere with thetest. However, in some embodiments, a measurement zone or region of thesecond vessel comprises a non-magnetic material such that the test maybe performed. For example, the measurement zone of the second vesselcomprises a non-metallic material such that the test may be performed.For example, the measurement zone of the second vessel may comprisenon-magnetic and/or non-metallic material such that the test may beperformed. In certain embodiments, the measurement zone of the secondvessel is the region of the vessel and the volume contained within thatregion that may be measured by a test when the second vessel isappropriately placed in a test instrument. In certain embodiments, themeasurement zone of the second vessel also includes the region of thevessel and the volume contained within that region that may influence atest, for instance, by negatively interfering with the test even whennot directly measured when the second vessel is appropriately placed ina test instrument. In certain embodiments, the measurement zone of thesecond vessel is the region where the cores are housed within the secondvessel. In certain embodiments, the measurement zone of the secondvessel is the region where the cores are housed within the secondvessel, in addition to about an inch away from the end cores. In certainexemplary embodiments, the measurement zone of the second vessel is theregion where the cores are housed within the second vessel, in additionto about two inches away from the end cores.

In some embodiments, the non-magnetic material comprises a non-magneticalloy, alumina, titanium, fiberglass, polyether ether ketone (PEEK),glass-fiber filled PEEK, a PEEK composite, polyphenylene sulfide (PPS),glass-fiber filled PPS, a PPS composite, polytetrafluoroethylene (PTFE),glass-fiber filled PTFE, a PTFE composite, a thermalplastic composite, aceramic, or any combination thereof. In one embodiment, the secondvessel (e.g., non-magnetic, non-metallic, or any combination thereof) isconstructed of a thermoplastic liner and with a titanium endcap andtitanium ball-valve flange interface. In one embodiment, the endcap andthe interface are integrally wound to a fiber overwrap and are sealedwith O-rings. As will be discussed further at 215, transferring the coresample from the first vessel to the second vessel allows the test to beperformed on the core sample in the second vessel. Furthermore, the coresample is transferred while maintaining pressure and/or temperature,which may lead to test results more representative of reservoirconditions.

In one embodiment, the first vessel encloses the core sample in a sealedchamber at a pressure above ambient pressure. For example, the firstvessel encloses the core sample at a pressure representative of apressure from which the core sample was retrieved from the wellbore ofthe subterranean reservoir. In some embodiments, the first vesselencloses the core sample at a pressure of at least 100 psi (e.g., atleast 200 psi, at least 300 psi, at least 400 psi, at least 500 psi, atleast 600 psi, at least 700 psi, at least 800 psi, at least 900 psi, atleast 1,000 psi, at least 1,500 psi, at least 2,000 psi, at least 2,500psi, at least 3,000 psi, at least 3,500 psi, at least 4,000 psi, atleast 4,500 psi, at least 5,000 psi, at least 5,500 psi, at least 6,000psi, at least 6,500 psi, at least 7,000 psi, at least 7,500 psi, atleast 8,000 psi, at least 8,500 psi, at least 9,000 psi, or at least9,500 psi). In some embodiments, the first vessel encloses the coresample at a pressure of 10,000 psi or less (e.g., 9,500 psi or less,9,000 psi or less, 8,500 psi or less, 8,000 psi or less, 7,500 psi orless, 7,000 psi or less, 6,500 psi or less, 6,000 psi or less, 5,500 psior less, 5,000 psi or less, 4,500 psi or less, 4,000 psi or less, 3,500psi or less, 3,000 psi or less, 2,500 psi or less, 2,000 psi or less,1,500 psi or less, 1,000 psi or less, 900 psi or less, 800 psi or less,700 psi or less, 600 psi or less, 500 psi or less, 400 psi or less, 300psi or less, or 200 psi or less). In one embodiment, the range may go upto about 15,000 or 20,000 psi. In one embodiment, for example, forunconventional assets, the range of pressure may be 12,000-15,000 psi.The first vessel encloses the core sample at a pressure in an amountranging from any of the minimum values described above to any of themaximum values described above. For example, the first vessel enclosesthe core sample at a pressure between 100 psi and 10,000 psi (e.g.,between 1,000 psi and 10,000 psi, between 4,000 psi and 8,000 psi,between 2,000 psi and 6,000 psi, between 4,000 psi and 7,000 psi, orbetween 5,000 psi and 10, 000 psi).

The core sample is maintained at a substantially equivalent pressure orplaced under a higher pressure during the transfer of the core samplefrom the first vessel to the second vessel. “Higher pressure” refers to1%-5% in one embodiment, 5%-10% in another embodiment, 1%-10% in anotherembodiment, 1%-15% in another embodiment, 1%-20% in another embodiment,or 1%-25% in another embodiment. For example, at least one pressuremeasurement apparatus (e.g., pressure sensor or gauge) associated withthe first vessel may be utilized to determine the pressure associatedwith the first vessel. Similarly, at least one pressure measurementapparatus (e.g., pressure sensor or gauge) associated with the secondvessel may be utilized to determine the pressure associated with thesecond vessel. The pressure associated with the first vessel may beutilized to set or adjust the pressure associated with the second vesselsuch that the core sample is maintained at a substantially equivalentpressure or placed under a higher pressure during the transfer of thecore sample from the first vessel to the second vessel.

Furthermore, in one embodiment, the core sample is maintained at asubstantially equivalent temperature or higher temperature during thetransfer of the core sample from the first vessel to the second vessel.“Higher temperature” refers to 1%-5% in one embodiment, 5%-10% inanother embodiment, 1%-10% in another embodiment, 1%-15% in anotherembodiment, 1%-20% in another embodiment, or 1%-25% in anotherembodiment. In some embodiments, the temperature is at least 100 degreesFahrenheit (e.g., at least 150 degrees Fahrenheit, at least 200 degreesFahrenheit, at least 250 degrees Fahrenheit, at least 300 degreesFahrenheit, or at least 350 degrees Fahrenheit). In some embodiments,the temperature is 400 degrees Fahrenheit or less (e.g., 350 degreesFahrenheit or less, 300 degrees Fahrenheit or less, 250 degreesFahrenheit or less, 200 degrees Fahrenheit or less, or 150 degreesFahrenheit or less). The temperature can be present in an amount rangingfrom any of the minimum values described above to any of the maximumvalues described above. For example, in some embodiments, thetemperature can be between 100 degrees Fahrenheit and 400 degreesFahrenheit (e.g., between 150 degrees Fahrenheit and 350 degreesFahrenheit, between 200 degrees Fahrenheit and 400 degrees Fahrenheit,between 300 degrees Fahrenheit and 400 degrees Fahrenheit, or between250 degrees Fahrenheit and 400 degrees Fahrenheit).

For example, at least one temperature measurement apparatus (e.g.,temperature sensor or gauge) associated with the first vessel may beutilized to determine the temperature associated with the first vessel.Similarly, at least one temperature measurement apparatus (e.g.,temperature sensor or gauge) associated with the second vessel may beutilized to determine the temperature associated with the second vessel.The temperature associated with the first vessel may be utilized to setor adjust the temperature associated with the second vessel such thatthe core sample is maintained at a substantially equivalent temperatureor higher temperature during the transfer of the core sample from thefirst vessel to the second vessel.

Turning to the transfer, as described previously with respect to FIG. 1,the core sample from the first vessel (e.g., the first vessel associatedwith a coring tool) may be transferred to the second vessel (e.g., thesecond vessel associated with a transfer tool). Coring tools (such ascommercially available coring tools) may be utilized as-is, or modified,for transferring the core sample from the first vessel to the secondvessel. Some embodiments, such as embodiments of the first vessel, thesecond vessel, and the transfer tool, are discussed in the U.S. patentapplication Ser. No. 16/944,542, filed Jul. 31, 2020, and titled“Pressurized Reservoir Core Sample Transfer Tool System,” the entirecontent of which is incorporated herein by reference.

In some embodiments, the entire contents of the first vessel may betransferred to the second vessel while maintaining pressure and/ortemperature. In some embodiments, less than the entire contents of thefirst vessel may be transferred to the second vessel while maintainingpressure and/or temperature. In some embodiments, the second vessel mayreceive the transferred core sample from the first vessel. For example,a single core sample can be transferred to the second vessel. Forexample, a plurality of core samples from a single first vessel (e.g., asingle first vessel of a coring tool) can each be transferred toindividual second vessels, in several groups to multiple second vessels,or all to a single second vessel. The multiple second vessels might eachbe designed for different tests or laboratory measurements, or they maybe compatible with multiple tests or measurements. As a plurality ofcore samples are taken from a single subsurface zone of interest inorder to minimize cross-contamination of varying fluid compositions, itmay not be necessary to perform the same test or measurement on multiplecore samples from the same zone.

At 210, the method 200 optionally includes using a non-hydrogenatedfluid during the transfer of the core sample from the first vessel tothe second vessel. In some embodiments, a non-hydrogenated fluidpreserves the core sample in the first vessel. In some embodiments, anon-hydrogenated fluid preserves the core sample in the second vessel.In some embodiments, the non-hydrogenated fluid comprises afluorocarbon.

At 215, the method 200 includes performing a test on the core sample inthe measurement zone of the second vessel. For example, the secondvessel having the core sample may be inserted into an apparatus (e.g., anuclear magnetic resonance (NMR) spectrometer) and a test may beperformed on the core sample.

In one embodiment, the test performed on the core sample comprises amagnetic resonance test. In one embodiment, the magnetic resonance testcomprises NMR. In one embodiment, the magnetic resonance test comprisesmagnetic resonance imagining (MRI). In one embodiment, the magneticresonance test comprises NMR and MRI.

NMR testing is discussed further in the following items: (a) U.S. Pat.No. 10,228,336 (Atty. Dkt. No. T-9935), (b) U.S. Pat. No. 10,145,810(Atty. Dkt. No. T-10017), (c) U.S. Patent App. Pub. No. 2017/0030845(Atty. Dkt. No. T-10177), (d) U.S. Patent App. Pub. No. 2017/0285215(Atty. Dkt. No. T-10368), (e) Chen, Z., Singer, P. M., Wang, X.,Hirasaki, G. J., & Vinegar, H. J. (2019, June 15). Evaluation of LightHydrocarbon Composition, Pore Size, and Tortuosity in Organic-RichChalks Using NMR Core Analysis and Logging. Society of Petrophysicistsand Well-Log Analysts. SPWLA 60^(th) Annual Logging Symposium, Jun.15-19, 2019, (f) Sakuraf, S., Loucks, R. G., & Gardner, J. S. (1995 Jan.1). Nmr Core Analysis Of Lower San Andres/Glorieta/Upper Clear Fork(Permian) Carbonates: Central Basin Platform, West Texas. Society ofPetrophysicists and Well-Log Analysts. SPWLA 36^(th) Annual LoggingSymposium, pages 1-12, Jun. 26-29, 1995, and (g) Shafer, J. (2013 Dec.1). Recent Advances in Core Analysis. Society of Petrophysicists andWell-Log Analysts. SPWLA-2013-v54n6-A4, (b) Unalmiser, S., & Funk, J. J.(1998 Apr. 1). Engineering Core Analysis. Society of PetroleumEngineers. SPE-36780-JPT, each of which is incorporated by reference.However, those of ordinary skill in the art will appreciate thatpractically any magnetic resonance test known to those of ordinary skillin the art may be performed on the core sample.

MRI testing is discussed further in the following items: (a) Robinson,M. A., Deans, H. A., & Bansal, S. (1992 Jan. 1). Determination of OilCore Flow Velocities and Porosities Using MRI. Society of PetroleumEngineers. SPE-23960-MS, (b) Cano-Barrita, P. F. de S., Balcom, B. J.,Green, D., McAloon, M., & Dick, J. (2008 Jan. 1). Capillary PressureMeasurement in Petroleum Reservoir Cores with MM. Offshore TechnologyConference. OTC 19234, and (c) Denney, T. (2008 Aug. 1). CapillaryPressure Measurement on Cores by MRI. Society of Petroleum Engineers.0808-0063-PT SPE, pages 63-66, each of which is incorporated byreference. However, those of ordinary skill in the art will appreciatethat practically any magnetic resonance test known to those of ordinaryskill in the art may be performed on the core sample.

In one embodiment, the test performed on the core sample comprises acomputed tomography (CT) test. CT testing is discussed further in thefollowing items: (a) Hidajat, I., Mohanty, K. K., Flaum, M., & Hirasaki,G. (2004 Oct. 1). Study of Vuggy Carbonates Using NMR and X-Ray CTScanning. Society of Petroleum Engineers. SPE 88995-PA, (b) Closmann, P.J., & Vinegar, H. J. (1993 Sep. 1). A Technique For Measuring Steam AndWater Relative Permeabilities At Residual Oil In Natural Cores: CT ScanSaturations. Petroleum Society of Canada. JCPT93-09-08, and (c) Arns, C.H., Sakellariou, A., Senden, T. J., Sheppard, A. P., Sok, R. M.,Knackstedt, M. A., Bunn, G. F. (2003 Jan. 1). Virtual Core Laboratory:Properties of Reservoir Rock Derived From X-ray CT Images. Society ofExploration Geophysicists, SEG-2003-1477, each of which is incorporatedby reference. However, those of ordinary skill in the art willappreciate that practically any computed tomography test known to thoseof ordinary skill in the art may be performed on the core sample.

In one embodiment, the test performed on the core sample comprises aneutron test. Neutron testing is discussed further in the followingitems: (a) Jasti, J. K., Lindsay, J. T., & Fogler, H. S. (1987 Jan. 1).Flow Imaging in Porous Media Using Neutron Radiography. Society ofPetroleum Engineers. doi:10.2118/16950-MS, SPE 16950 and (b) Nicholls,C. I., & Heaviside, J. (1988 Mar. 1). Gamma-Ray-Absorption TechniquesImprove Analysis of Core Displacement Tests. Society of PetroleumEngineers. SPE 14421-PA. each of which is incorporated by reference.Those of ordinary skill in the art will appreciate that practically anyneutron test known to those of ordinary skill in the art may beperformed on the core sample.

In one embodiment, the test performed on the core sample comprises anacoustic test. In one embodiment, the acoustic test comprises acousticresonance technology (ART) or acoustic resonance (AR). Acoustic testingis discussed further in the following item: (a) Sivaraman, A., Hu, Y.F., Thomas, F. B., Bennion, D. B., & Jammaluddin, A. K. M. (1998 Jan.1). Determination of Phase Transitions In Porous Media Using AcousticTechnology. Petroleum Society of Canada. PETSOC-98-75, which isincorporated by reference. Those of ordinary skill in the art willappreciate that practically any acoustic test known to those of ordinaryskill in the art may be performed on the core sample.

In one embodiment, the test performed on the core sample comprises adielectric test. Dielectric testing is discussed further in thefollowing items: (a) Leung, P. K., & Steig, R. P. (1992 Jan. 1).Dielectric Constant Measurements: A New, Rapid Method To CharacterizeShale at the Wellsite. Society of Petroleum Engineers. IADC/SPE 23887-MSand (b) Ali A. Garrouch, (2018), “Predicting the cation exchangecapacity of reservoir rocks from complex dielectric permittivitymeasurements,” GEOPHYSICS, Volume 83, Issue 1, MR1-MR14 (January 2018),each of which is incorporated by reference. Those of ordinary skill inthe art will appreciate that practically any dielectric test known tothose of ordinary skill in the art may be performed on the core sample.

In one embodiment, the test performed on the core sample comprises amagnetic resonance test, a computed tomography test, a neutron test, anacoustic test, a dielectric test, or any combination thereof. Those ofordinary skill in the art will appreciate that this is not an exhaustivelist, and at least one test not listed herein may be performed in oneembodiment. For example, in some embodiments, the test(s) discussed inthe following item may be utilized: Aidan Blount, et al, “Maintainingand Reconstructing In-Situ Saturations: A Comparison Between Whole Core,Sidewall Core, and Pressurized Sidewall Core in the Permian Basin,”Petrophysics 60, 50-60 (2019), which is incorporated by reference.

The test results may be utilized in a variety of ways, as discussedhereinbelow at 220, 225, 230, 235, 240, 245, 250, or any combinationthereof.

At 220, the method 200 includes determining (e.g., determining,measuring, etc.) a fluid saturation of the core sample using the test.For example, the tests discussed herein may be utilized to analyze thefluid composition of the core sample that has remained at elevatedpressure and/or elevated temperature during retrieval from thesubterranean reservoir to the laboratory. For example, one or more ofthe tests may be utilized for petrophysical analysis to determine thefluid saturation of the subterranean reservoir as a function of depth—inother words, the identity and relative amount of fluids present in thepore volume, including liquid hydrocarbons, water, and gas (hydrocarbonand otherwise)—in order to identify the optimal zone(s) for economicproduction of hydrocarbons. Those of ordinary skill in the art willappreciate that the test results may be utilized to determine the fluidsaturation of the core sample.

Fluid saturations are conventionally determined using one or morelaboratory samples that have already undergone compositional changesfrom their native state. However, in some embodiments the pressureand/or temperature of the first vessel has been maintained atrepresentative conditions during retrieval from the reservoir in orderto minimize or eliminate structural changes to the sample and/or phaseor composition changes to the fluids contained in the sample.Additionally, as disclosed herein, the core sample is maintained at asubstantially equivalent pressure or placed under a higher pressureduring the transfer of the core sample from the first vessel to thesecond vessel. Moreover, in some embodiments, the core sample ismaintained at a substantially equivalent temperature or highertemperature during the transfer of the core sample from the first vesselto the second vessel. By doing so, compositional changes in the coresample may be reduced (or completely avoided) and the core sample may becloser to its native state during testing in the second vessel, whichmay lead to more accurate test results.

At 225, the method 200 optionally includes calibrating test measurementson at least one other core sample performed at ambient pressure usingthe determined fluid saturation. For example, the observed changes canbe analyzed to create a calibration for standard laboratory measurementsperformed at ambient pressure on regular core samples (i.e., coresamples that have not maintained pressure and/or temperature) taken fromthe same subterranean reservoir, so that the determined fluid saturationcan be related to the probable native fluid saturation in thesubterranean reservoir. Extraction of pressure-preserved core samples isexpected to be significantly more expensive than standard (notpressure-preserving) coring services, so it is beneficial to primarilycollect regular core samples with only a few pressure-preserved coresamples for calibration. This process enhances the accuracy of thecore-to-log calibration for laboratory measurements performed on theregular core samples, and therefore, ultimately the accuracy of thereservoir models used to make business decisions about which reservoirsto produce for oil and/or gas.

At 230, the method 200 optionally includes reducing the pressure on thecore sample in the second vessel; and repeating the test on the coresample in the second vessel. For example, the pressure of the coresample may be reduced, step by step, to ambient pressure.

At 235, the method 200 optionally includes reducing the temperature onthe core sample in the second vessel; and repeating the test on the coresample in the second vessel. For example, the temperature of the coresample may be reduced, step by step, to ambient temperature.

In one embodiment, the pressure only is reduced (at 230). In oneembodiment, the temperature only is reduced (at 235). In one embodiment,the pressure and temperature are reduced. As another example, reductionof pressure may occur, reducing in multiple steps may occur, with testmeasurements in between may occur. Those of ordinary skill in the artwill appreciate that many options are possible.

At 240, the method 200 optionally includes injecting a chemical agent(e.g., fluorocarbon) into the second vessel to preserve fluid saturationof the core sample to allow for testing of the core sample at ambientpressure conditions outside the second vessel. For example, thepreservation may not affect geomechanical properties of the core sample.

At 245, the method 200 optionally includes cooling the core sample inthe second vessel to preserve fluid saturation of the core sample toallow for testing of the core sample at ambient pressure conditionsoutside the second vessel. For example, the preservation may not affectgeomechanical properties of the core sample.

At 250, the method 200 optionally includes injecting a chemical agent(e.g., a resin, a polymer, an alloy, or any combination thereof) intothe second vessel to encase the core sample to preserve fluid saturationof the core sample to allow for testing of the core sample at ambientpressure conditions outside the second vessel. For example, a resin, apolymer, an alloy, or any combination thereof may be selected so thatthey do not affect geomechanical properties of the core sample.

EXAMPLE: A NMR example will now be discussed, and a similar approach maybe utilized with the other tests. NMR is utilized for measuringsaturation, and NMR distinguishes between fluids based on differences inparameters of the detected magnetic resonance signals, including signalrelaxation times (referred to as T1 and T2) and measured diffusioncoefficients. Different excitation and measurement sequences areemployed to enable sensitivity to these parameters, and they areoptimized for the expected values in a given reservoir. NMR data may berepresented as 1-, 2-, or 3-dimensional spectra, where the axes canrepresent values of T1 and T2 relaxation times and diffusioncoefficients. Downhole NMR logging tools can provide saturation valueswith spatial resolution on the order of one or several feet of depth,but NMR log data is best calibrated against laboratory measurementsperformed under both as-received and controlled saturation conditions,using typically 5 to 30 core samples per well.

All measurements described in this example involve first transferringthe core samples from a first vessel of a commercial coring tool atelevated pressure to a second vessel(s) that is designed to becompatible with the measurement technologies intended for use with thosecore samples, while maintaining pressure. In certain embodiments, suchas in the case of NMR measurements, this may involve designing thesecond vessel to contain only non-magnetic components and designing themeasurement zone of the second vessel to contain only non-metallic andlow/no noise components. The coring tool may also contain at least onenon-hydrogenated fluid, such as a fluorocarbon, which may be chosen tobe both non-wetting on the rock material and non-miscible withhydrocarbons and water, and thus assist in maintaining the fluidsaturations within the core samples. The non-hydrogenated fluid can alsobe transferred to the second vessel without interfering with hydrogenNMR measurements. Core samples from a single coring tool can each betransferred to individual second vessels, in several groups to multiplesecond vessels, or all to a single second vessel. The multiple secondvessels might each be designed for different laboratory measurements ortests, or they may be compatible with multiple measurements or tests. Asa plurality of core samples are taken from a single subsurface zone ofinterest in order to minimize cross-contamination of varying fluidcompositions, it may not be necessary to perform the same test ormeasurement on multiple core samples from the same zone.

NMR measurements can be performed on the core sample(s) at the initialpressure and/or temperature, then at intermediate pressure values and/ortemperature values as the second vessel is depressurized. The NMR datacan be used to determine the fluid saturations at each step. Theobserved changes can be analyzed to create a calibration for standardlaboratory measurements performed at ambient pressure on regular coresamples (i.e., samples not extracted by a tool that preserves pressure)taken from the same formation, so that the measured fluid saturation canbe related to the probable native fluid saturation in the subterraneanreservoir. Extraction of pressure-preserved core samples is expected tobe significantly more expensive than standard (not pressure-preserving)coring services, so it is beneficial to primarily collect regular coresamples with only a few pressure-preserved core samples for calibration.This process enhances the accuracy of the core-to-log calibration forlaboratory measurements performed on the regular core samples, andtherefore ultimately the accuracy of the reservoir models used to makebusiness decisions about which reservoirs to produce for oil and/or gas.

NMR spectrometers are available in a range of magnetic field strengths(and some have variable field strength), with different field strengthsoffering advantages and disadvantages depending on the intendedapplication. It is customary to describe an instrument in terms of itsproton magnetic resonance frequency, which is directly proportional tothe field strength (the constant of proportionality is the protongyromagnetic ratio, 42.6 MHz/Tesla). For example, NMR logging tools aregenerally in the range of 500 kHz-2 MHz, and laboratory NMR devices usedfor log calibration are typically at around 2 MHz, with systems in therange of 10-20 MHz becoming more common for tight rock unconventionalsamples. For purposes of determining fluid saturations, instruments atparticular field strengths may be advantageous for discriminatingbetween certain fluid types.

In some embodiments, the field strength is at least 0.5 MHz (e.g., atleast 1 MHz, at least 10 MHz, at least 20 MHz, at least 30 MHz, at least40 MHz, at least 50 MHz, at least 60 MHz, at least 70 MHz, at least 80MHz, or at least 90 MHz). In some embodiments, the field strength is 100MHz or less (e.g., 90 MHz or less, 80 MHz or less, 70 MHz or less, 60MHz or less, 50 MHz or less, 40 MHz or less, 30 MHz or less, 20 MHz orless, or 10 MHz or less). The magnetic field strength can be present inan amount ranging from any of the minimum values described above to anyof the maximum values described above. For example, in some embodiments,the magnetic field strength may be between 0.5 MHz and 100 MHz (e.g.,between 0.5 and 4 MHz, between 4 and 20 MHz, between 20 and 60 MHz, orbetween 60-100 MHz). In some embodiments, the magnetic field strength ofany commercially available NMR spectrometer may be utilized (e.g., up to1.2 GHz). In some embodiments, magnetic field strengths of approximately2 MHz and 42 MHz may be utilized. Although data from one measurementfrequency may be sufficient, comparing the NMR data at these twofrequencies may aid in determining fluid saturations in the coresamples. These values are determined by the instruments available in ourlaboratory, and they may not be optimal for the fluids present in aparticular reservoir. The ideal measurement frequencies for particularrock and/or fluid types (such as in the unconventional area) is asubject of ongoing research, so tests may be applied using instrumentswith other values of the NMR measurement frequencies, or using adifferent number of measurement frequencies.

NMR spectra, in particular those that include T1 and/or T2 axes, can beused to characterize the sizes and types of pores in a sample, and thefluids contained therein (both quantity and kind). For example, in ashale sample, the NMR spectrum can distinguish between organic andinorganic pores. In a core sample from a conventional reservoir (such asa carbonate or sandstone), the NMR spectrum can be related to thedistribution of pore sizes present. Clay-bound and/or capillary-boundfluids can also be distinguished from free fluid. As a core sample isdepressurized, measured changes in the NMR spectrum can be analyzed todetermine changes in the fluid saturations of different subsets of poresin the sample, such as different pore types or different pore sizes.

Precise chemical compositions of the fluids in these pore subsets can bedetermined by also performing geochemical analysis (such as gaschromatography) on the gases released from the core samples, andsubsequently expelled from the second vessel, at each depressurizationstep. The observed sequence of chemicals identified at each pressure,and the corresponding changes in the NMR spectrum, describe theparticular fluids expected to be recovered as the pressure drops in areservoir during production, including in what pressure range each fluidwill be recovered and from which pores.

Although the total quantity of fluid produced is of interest, andpotentially the quantities of particular kinds of fluids (such ashydrocarbons in general, or particular kinds of hydrocarbon), it is notnecessarily viable to completely deplete an individual reservoir duringproduction. The methods described here can therefore be used tocharacterize well productivity in specific pressure ranges. The rate ofdepressurization can also be varied between samples, in order to studyhow the depletion rate affects the ultimate productivity of a particularreservoir. NMR and/or geochemistry can be performed as the depletionprogresses, in order to quantify how the depletion rate affects whichfluids are expelled at a given pressure, and from which pores. Thisinformation can be used to optimize aspects of the production design,such as the pressure depletion window and the depletion rate (set forinstance by the choke size at the wellhead). Studying how to optimizethe depletion rate for total productivity can also lead to an improvedestimate of ultimate recovery (EUR), which is a metric for reservesbooking.

The physical phases of the individual fluids may change duringdepressurization, if those fluids pass through phase boundaries (such asat the dew and/or bubble points) at a given temperature. This phasebehavior cannot be easily predicted or measured in some systems, such asnanoscale pores in shale, but systems and methods for using NMR toobserve and characterize phase behavior and measure phase boundaries insuch systems, as in U.S. Pat. No. 10,634,746, which is incorporated byreference, may be used. The methods described there can be applied tothe pressurized core samples described in this disclosure. For example,as the pressure is reduced, a change in some NMR parameter associatedwith a particular fluid (such as T2) may indicate a change in the phaseof that fluid. As discussed herein, the native fluids present in thecore sample, rather than loading a fluid into the sample in thelaboratory and then pressurizing, may be advantageous because themeasurements would be more readily applicable to the specific rock/fluidsystem of a particular reservoir.

These NMR methods can also be applied using magnetic resonance imaging(MRI) techniques, which allow for 1-D, 2-D, and/or 3-D spatial imagingof various NMR parameters, such as fluid quantities (e.g., total and/oreffective porosity) or relaxation parameters (T1, T2). Different regionsof a sample may contain different fluid saturations, or they may exhibitdifferent saturation changes or phase behavior as a function ofpressure, all of which could be measured and imaged using MM. Physicalchanges to the rock during depressurization, such as fracturing or otherdamage, can also be observed by MRI. These changes can be correlatedwith the fluid saturations and pore properties present in the sample, orin the specific regions of the sample where the changes occur.

Samples can also be imaged using CT methodologies (which may requiredifferent second vessel designs), which typically can have finer spatialresolution than MRI but less sensitivity to fluid saturation, and theimages correlated with the NMR and/or MM measurements. For example, CTimages may be used to monitor the orientation of fractures, both thosepresent in a sample as received and those induced duringdepressurization. In addition, MRI and/or CT can be used to determinethe sizes and positions of individual samples in a second vesselcontaining multiple samples, in case the second vessel is opaque tovisible light or other imaging methods.

In contrast to existing tools and methodologies, embodiments consistentwith this disclosure may allow measurement of in-situ water saturationsand the salinity of the pore water/original reservoir brine, twoparameters that are important for reservoir characterization.Furthermore, embodiments consistent with this disclosure can potentiallybe used to measure relative permeability under more accurate conditions.The embodiments consistent with this disclosure may allow determinationof effective porosity at in-situ reservoir conditions.

All methods discussed here can also be applied to study samples as thetemperature is decreased in steps to ambient temperature, potentially incombination with decreases in pressure (either simultaneous orsequential). In addition, NMR/MRI can also characterizetemperature-dependent changes in fluid viscosity, wettability,asphaltene precipitation, and wax precipitation.

MODIFICATIONS: Those of ordinary skill in the art will appreciate thatvarious modifications may be made to the embodiments provided herein.For example, one embodiment may involve transferring at least a portionof a core sample from the first vessel to a plurality of vessels. Thecore sample is maintained at a substantially equivalent pressure orplaced under a higher pressure during the transfer of the core samplefrom the first vessel to the plurality of vessels. Furthermore, in oneembodiment, the core sample is maintained at a substantially equivalenttemperature or higher temperature during the transfer of the core samplefrom the first vessel to the plurality of vessels.

What is claimed is:
 1. A method of performing a test on a core sample,the method comprising: transferring at least a portion of a core samplefrom a first vessel to a second vessel, wherein the core sample ismaintained at a substantially equivalent pressure or placed under ahigher pressure during the transfer of the core sample from the firstvessel to the second vessel; and performing a test on the core sample inthe second vessel.
 2. The method of claim 1, wherein the test on thecore sample is unable to be performed using the first vessel due tointerference between the first vessel and equipment used for the test.3. The method of claim 1, wherein the core sample comprises one or moreselected from the group consisting of: rock and fluid samples retrievedfrom a wellbore of a subterranean reservoir using a rotary sidewallcoring process, a plurality of rock and fluid samples retrieved fromvarious depths in a wellbore of a subterranean reservoir using a rotarysidewall coring process, and rock and fluid retrieved from a wellbore ofa subterranean reservoir using a pressure coring process.
 4. The methodof claim 1, wherein the first vessel encloses the core sample in asealed chamber at a pressure above ambient pressure.
 5. The method ofclaim 4, wherein the core sample is enclosed within the first vessel,and wherein the core sample is maintained at a pressure representativeof a pressure from which the core sample was retrieved from thesubterranean reservoir.
 6. The method of claim 1, wherein the firstvessel comprises a magnetic material, a metallic material, or both; andwherein a measurement zone of the second vessel comprises a non-metallicmaterial, non-magnetic material, or both.
 7. The method of claim 6,wherein the non-magnetic material comprises a non-magnetic alloy,alumina, titanium, fiberglass, polyether ether ketone (PEEK),glass-fiber filled PEEK, a PEEK composite, polyphenylene sulfide (PPS),glass-fiber filled PPS, a PPS composite, polytetrafluoroethylene (PTFE),glass-fiber filled PTFE, a PTFE composite, a thermalplastic composite, aceramic, or any combination thereof.
 8. The method of claim 1, whereinthe core sample is maintained at a substantially equivalent temperatureor higher temperature during the transfer of the core sample from thefirst vessel to the second vessel.
 9. The method of claim 8, furthercomprising: reducing the temperature on the core sample in the secondvessel; and repeating the test on the core sample in the second vessel.10. The method of claim 1, wherein the test comprises a magneticresonance test, a computed tomography test, a neutron test, an acoustictest, a dielectric test, or any combination thereof.
 11. The method ofclaim 10, wherein the magnetic resonance test is performed at aplurality of measurement frequencies.
 12. The method of claim 10,wherein the magnetic resonance test is used to determine at least one ofa porosity of the core sample, a permeability of the core sample, achemical composition of the core sample, a chemical shift of the coresample, a pore size distribution of the core sample, one or moremolecular weights of any hydrocarbons contained within the core sample,relaxation times of the core sample, diffusion coefficients of the coresample, or any combinations thereof.
 13. The method of claim 10, whereinthe magnetic resonance test comprises a magnetic resonance imaging test.14. The method of claim 1, further comprising: reducing the pressure onthe core sample in the second vessel; and repeating the test on the coresample in the second vessel.
 15. The method of claim 14, furthercomprising determining a change in the phase of a fluid contained in thecore sample due to the reduction in pressure.
 16. The method of claim14, further comprising creating a model of hydrocarbon production as afunction of pressure for the subterranean reservoir from which the coresample was retrieved.
 17. The method of claim 16, further comprisingdetermining the optimum depletion rate for the subterranean reservoir.18. The method of claim 1, further comprising transferring at least aportion of a core sample from the first vessel to a plurality ofvessels, wherein the core sample is maintained at a substantiallyequivalent pressure or placed under a higher pressure during thetransfer of the core sample from the first vessel to the plurality ofvessels.
 19. The method of claim 1, further comprising using the test todetermine one or more of the following: a fluid saturation of the coresample, a spatial distribution of fluid saturations within the coresample, a salinity of a brine contained in the core sample, and aneffective porosity of the core sample.
 20. The method of claim 19,further comprising calibrating test measurements on at least one othercore sample performed at ambient pressure using the determined fluidsaturation
 21. The method of claim 1, further comprising injecting achemical agent into the second vessel to preserve fluid saturation ofthe core sample to allow for testing of the core sample at ambientpressure conditions outside the second vessel.
 22. The method of claim1, further comprising cooling the core sample in the second vessel topreserve fluid saturation of the core sample to allow for testing of thecore sample at ambient pressure conditions outside the second vessel.23. The method of claim 1, wherein a non-hydrogenated fluid preservesthe core sample in the first vessel, a non-hydrogenated fluid preservesthe core sample in the second vessel, and a non-hydrogenated fluid isused during the transfer of the core sample from the first vessel to thesecond vessel.
 24. The method of claim 23, wherein the non-hydrogenatedfluid comprises a fluorocarbon.
 25. The method of claim 1, wherein thesecond vessel comprises a measurement zone, wherein the measurement zoneis constructed by wrapping a low or no noise resin and fiber materialaround a tube, wherein the tube is constructed from a non-metallicmaterial, a non-magnetic material, or both.